BY HAND DELIVERY AND ELECTRONIC MAIL...17 Engineerin g as an Electrical Engineer I. From January...

40 Sylvan Road, Waltham, MA 02451T: [email protected] www.nationalgrid.com

December 4, 2018

BY HAND DELIVERY AND ELECTRONIC MAIL

Luly E. Massaro, Commission ClerkRhode Island Public Utilities Commission89 Jefferson BoulevardWarwick, RI 02888

RE: Docket 4889 - The Narragansett Electric Company, d/b/a National Grid2019 System Reliability Procurement ReportJoint Pre-Filed Direct Testimony

Dear Ms. Massaro:

On behalf of National Grid, I have enclosed eleven copies of the Joint Pre-filed DirectTestimony of Matthew Chase, Ryan Constable, Stephen Lasher, and Timothy Roughan in theabove-referenced docket.

Thank you for your attention to this filing. If you have any questions, please contact meat 781-907-2121.

Very truly yours,

Raquel Webster

Enclosures

cc: Dockets 4888/4889 Service ListsJon Hagopian, Esq.John Bell, Division

Raquel WebsterSenior Counsel

Certificate of Service I hereby certify that a copy of the cover letter and any materials accompanying this certificate was electronically transmitted to the individuals listed below. The paper copies of this filing are being hand delivered to the Rhode Island Public Utilities Commission and to the Rhode Island Division of Public Utilities and Carriers.

___________________________________ December 4, 2018 Joanne M. Scanlon Date Docket No. 4888 - National Grid – 2019 Energy Efficiency Plan (EEP) Docket No. 4889 - National Grid – 2019 System Reliability Procurement Report (SRP) Service list updated 10/18/18

Name/Address E-mail Distribution List Phone Raquel Webster, Esq. National Grid 280 Melrose St. Providence, RI 02907

[email protected]; 781-907-2121 [email protected]; [email protected]; [email protected]; [email protected]; [email protected];

Jon Hagopian, Esq. Division of Public Utilities and Carriers

[email protected]; 401-784-4775 [email protected];

[email protected];

[email protected]; [email protected]; [email protected];

Tim Woof Jennifer Kallay Synapse Energy Economics 22 Pearl Street Cambridge, MA 02139

[email protected];

[email protected];

Marisa Desautel, Esq. (EERMC) Law Office of Marisa Desautel, LLC 55 Pine St. Providence, RI 02903

[email protected]; 401-477-0023

Mike Guerard, Optimal Energy [email protected]; Mark E. LeBel, Esq. Acadia Center 31 Milk Street Suite 501 Boston, MA 02108

[email protected];

617-742-0054 Ext. 104 [email protected];

Carol Grant, Commissioner [email protected];

Office of Energy Resources (OER) [email protected]; [email protected] ; [email protected]; [email protected] ;

Andrew Marcaccio, Esq. Dept. of Administration Division of Legal Services One Capitol Hill, 4th Floor Providence, RI 02908

[email protected]; 401-222-8880

Larry Chretien, Executive Director Green Energy Consumers Alliance

[email protected];

Original & 9 copies file w/: Luly E. Massaro, Commission Clerk Public Utilities Commission 89 Jefferson Blvd. Warwick, RI 02888

[email protected]; 401-780-2107 [email protected];

[email protected]; [email protected] ; [email protected] ;

Frederick Sneesby Dept. of Human Services

[email protected];

Douglas W. Gablinske, Executive Director The Energy Council of RI (TEC-RI)

[email protected];

Kat Burnham, PPL [email protected]; Chris Vitale, Esq., RI Infrastructure Bank [email protected];

THE NARRAGANSETT ELECTRIC COMPANYd/b/a NATIONAL GRID

RIPUC DOCKET NO. 4889RE: 2019 SYSTEM RELIABILITY PROCUREMENT REPORT

WITNESSES: MATTHEW CHASE, RYAN CONSTABLE,STEPHEN LASHER, AND TIMOTHY ROUGHAN

DECEMBER 4, 2018

JOINT PRE-FILED DIRECT TESTIMONY

OF

MATTHEW CHASE, RYAN CONSTABLE,

STEPHEN LASHER, AND TIMOTHY ROUGHAN




DECEMBER 4, 2018

Table of Contents

I. Introduction ..........................................................................................................................1

II. Purpose of Joint Testimony..................................................................................................7

III. 2019 System Reliability Procurement Report ......................................................................8

IV. Consideration of NWAs in System Planning .....................................................................14

V. Tiverton-Little Compton NWA Project .............................................................................17

VI. South County East NWA Projects......................................................................................21

VII. Customer-Facing Program Enhancement Study ................................................................21

VIII. Rhode Island Locational Incentives ...................................................................................25

IX. SRP Incentive Mechanism Proposal ..................................................................................31

X. Conclusion..........................................................................................................................34




DECEMBER 4, 2018PAGE 1 OF 34

I. INTRODUCTION1

Q. Mr. Chase, please state your name and business address.2

A. My name is Matthew Chase. My business address is 477 Dexter Street, Providence,3

Rhode Island 02907.4

5

Q. Mr. Chase, by whom are you employed and in what position?6

A. I am employed by National Grid USA Service Company, Inc. (Service Company) as7

Engineer, Customer Reliability Analytics and NWA Solutions. I am responsible for the8

System Reliability Procurement (SRP) regulatory filing of The Narragansett Electric9

Company d/b/a National Grid (the Company or National Grid). I am also responsible for10

Non-Wires Alternative (NWA) projects in Rhode Island and Massachusetts.11

12

Q. Mr. Chase, please describe your educational background and professional experience.13

A. In 2014, I graduated from Worcester Polytechnic Institute with a Bachelor of Science Degree14

in Electrical and Computer Engineering. After graduating from Worcester Polytechnic15

Institute, I attended graduate school. In 2015, I was employed by Zachry Nuclear16

Engineering as an Electrical Engineer I. From January 2015 to April 2016, I performed17

various work involving design, construction, and implementation of electrical and nuclear18

systems. I then joined National Grid USA in May 2016 as an Associate Engineer in19

Advanced Grid Engineering of the Network Solutions group. In June 2017, I was promoted20

to Engineer into the Non-Wires Alternative Offerings group in New Energy Solutions at21





National Grid. From June 2017 to December 2017, I was a project engineer for NWA1

projects in Rhode Island and Massachusetts. In January 2018, I began my current position,2

which includes being lead program manager of the SRP Report.3

4

Q. Have you previously testified before the Rhode Island Public Utilities Commission5

(PUC)?6

A. No, I have not.7

8

Q. Mr. Constable, please state your name and business address.9

A. My name is Ryan M. Constable. My business address is 40 Sylvan Road, Waltham,10

Massachusetts 02451.11

12

Q. Mr. Constable, by whom are you employed and in what position?13

A. I am employed by the Service Company as Consulting Engineer in Grid Modernization14

Solutions.15

16

Q. Mr. Constable, please describe your educational background and professional17

experience.18

A. I received a Bachelor of Science in Electric Power Engineering from Rensselaer Polytechnic19

Institute in Troy, New York in 1993 and a Certificate of Industrial Management and Power20

Engineering from Worcester Polytechnic Institute in Worcester, Massachusetts in 2000. I am21





a Registered Professional Engineer in Massachusetts, number 41632. I worked at National1

Grid from 1994 to 2000 and 2010 to the present. I have held various positions of increasing2

responsibility in the area of Distribution Planning. From 1994 to 1998, I was a Project3

Engineer responsible for the design and maintenance of the electric infrastructure serving4

commercial and residential customers in southeastern Massachusetts. During the period 19985

to 2000, I was a Planning Engineer conducting long-range electric system studies. From 20106

to 2011, I worked as a Principal Engineer in the Utility of the Future department developing7

the Worcester Smart Energy Solution Pilot. In 2011, I became the Manager of Distribution8

Planning and Asset Management – New England, directing a ten-person team to conduct9

annual planning activities, perform long-range planning studies, and develop regulatory10

filings. In 2017, I became the Acting Director of the department. In the period 2000 to 2010,11

I worked for three independent transmission development companies, TransEnergie U.S.,12

Cross Sound Cable Company, and Brookfield Renewable Power.13

14

Q. Have you previously testified before the PUC?15

A. Yes.16

17

Q. Mr. Lasher, please state your name and business address.18

A. My name is Stephen Lasher. My business address is 477 Dexter Street, Providence,19

Rhode Island 02907.20

21





Q. Mr. Lasher, by whom are you employed and in what position?1

A. I am employed by the Service Company as a Principal Engineer in the Grid2

Modernization Solutions Group under the US Electric Business Unit. The Grid3

Modernization Solutions Group is responsible for supporting the Company's transition to4

the Modern Grid through identification and evaluation of potential next opportunities,5

technologies, or processes to provide measurable value. Such tasks will be done while6

remaining focused on the Company's 2030 Vision and fundamental goals to provide a7

safe, efficient, reliable, and sustainable system across all of National Grid USA.8

9

Q. Mr. Lasher, please describe your educational background and professional experience.10

A. I graduated from the University of Cincinnati with a Bachelor of Science Degree in Civil11

and Environmental Engineering in 1997, and from the Massachusetts Institute of12

Technology with a Master of Science Degree in Mechanical Engineering in 1999. From13

1999 to 2010, I was employed by Arthur D. Little Inc. and later by TIAX LLC, both14

Cambridge-based consulting and technology development companies, as a Consultant,15

Program Manager, Group Manager, and Business Development Leader. My16

responsibilities included the following: managing and leading technology assessment,17

research, and development programs for emerging energy technologies; managing and18

leading the Clean Energy and Fuels Group, which included a dozen engineers and19

scientists; leading technical marketing in the transportation, building technology,20

distributed generation, and portable power sectors; and acting as a government liaison and21





advocated for clean energy policy and funding support with the U.S. Department of1

Energy, U.S. Department of Defense, state agencies, and with members of Congress. From2

2010 to 2012, I was employed by Satcon Technology Corporation, a Boston-based solar3

inverter company, as their Director of Business Development for R&D and later as their4

Director of Product Management for Central Inverters. My responsibilities included the5

following: developing research, developing and demonstrating projects with government6

and commercial partners including solar energy, smart grid, energy storage, electric7

vehicle, and microgrid projects; managing the product lifecycle for existing central inverter8

products; and leading new inverter product strategy and roadmap development. From 20129

to 2014, I was self-employed as a consultant to various small businesses in Massachusetts10

and Rhode Island, where I provided technical and market insights for clients, drove new11

product development programs, and helped capture new business and outside funding12

opportunities for the development and commercialization of emerging energy technologies.13

From 2014 to 2015, I was employed by eNow Inc., a Warwick-based manufacturer of solar14

power solutions for the transportation sector, as their Vice President of Business15

Development. My responsibilities included the following: managing technical, regulatory,16

and marketing aspects of all products and services; growing partner relationships;17

developing strategic plans; and leading new product development programs. From 2015 to18

2016, I was employed by Sensata Technologies, Inc., an Attleboro-based supplier of19

sensors and controls for a broad range of markets and applications, as their North20

American Market Manager for Performance Sensors. My responsibilities included: leading21





US team to accelerate business growth; developing strategic plans and product road maps;1

and leading proposal and business case review for executive leadership approval. In April2

2016, I joined National Grid USA as a Principal Engineer in the Advanced Grid3

Engineering Group under the New Energy Solutions Business Unit. My responsibilities4

have included the following: technical lead for Niagara Mohawk Power Corporation’s5

(NMPC) Reforming the Energy Vision (REV) Distributed System Platform (DSP)6

Demonstration Project in Buffalo, New York; technical lead for National Grid’s Non-7

Wires Alternative (NWA) project deferral calculations; co-author of National Grid’s Grid8

Modernization Strategy Roadmap; business lead for the Narragansett Electric Company’s9

(NEC) Power Sector Transformation (PST) Grid Modernization Plan.10

11


A. No, I have not.13

14

Q. Mr. Roughan, please state your name and business address.15

A. My name is Timothy R. Roughan. My business address is 40 Sylvan Road, Waltham,16

MA 02451.17

18

Q. Mr. Roughan, by whom are you employed and in what position?19

A. I am employed by the Service Company as the Director of Regulatory Strategy for Rhode20

Island.21





Q. Mr. Roughan, please describe your educational background and professional1

experience.2

A. I have a BSME from WPI and have worked at National Grid USA and its predecessor3

companies since 1982 in a variety of roles. Recently, I have worked extensively on matters4

relating to distributed generation and non-wires alternatives.5

6


A. Yes, I have testified before the PUC in several dockets, the most recent being8

Docket 4770 and Docket 4780. I have also testified at previous SRP hearings since 2009.9

10

II. PURPOSE OF JOINT TESTIMONY11

Q. What is the purpose of this joint testimony?12

A. The purpose of this joint testimony is to present the 2019 SRP Report, which the13

Company developed as part of an iterative process with the Parties.12 As is described in14

the Report, implementation of the 2019 SRP Report will allow the Company to meet its15

obligation to provide safe, reliable, and efficient electric service for customers at16

reasonable cost.17

1 The 2019 SRP Report presented in this filing is the eighth annual plan submitted to the PUC pursuant to theprovisions of R.I. Gen. Laws § 39-1-27.7.7.

2 The Parties include the Rhode Island Division of Public Utilities and Carriers (Division), the Energy Efficiencyand Resource Management Council (EERMC), Acadia Center, Green Energy Consumers Alliance (formerlyPeople’s Power & Light), The Energy Council of Rhode Island, the Rhode Island Office of Energy Resources,and National Grid.





III. 2019 SYSTEM RELIABILITY PROCUREMENT REPORT1

Q. How did the Company prepare the 2019 SRP Report for review by the PUC?2

A. The Company prepared the first draft of the 2019 SRP Report, which it submitted to the3

Parties on August 13, 2018 for review. In preparing the 2019 SRP Report, the Company4

had meetings and discussions with members of the Rhode Island Energy Efficiency5

Collaborative (Collaborative).3 Meetings and discussion with Collaborative members6

continued through three draft versions up until October 4, 2018 when the Energy7

Efficiency and Resource Management Council (EERMC) voted on the 2019 SRP Report.8

In this filing, the Company has proposed a funding request for CY 2019 totaling9

$329,800. This proposed SRP funding request includes a range of project work that is10

required to maintain safe and reliable service and expand the Company’s capability to do11

so. The project work that is included in the 2019 SRP Report is specifically designed to12

meet system performance objectives and/or customer service requirements, which the13

Company must address as part of its public service obligation. In the Report, the14

Company has provided a detailed explanation of the categories of investment it plans to15

undertake, the factors motivating the nature and amount of investment to be completed,16

and the specific projects that will be undertaken in Rhode Island.17

18

3 Members of the Collaborative presently include the Company, the Division, the OER, TEC-RI, Green EnergyConsumers Alliance, Acadia Center, several EERMC members, and representatives from the EERMC’sConsulting Team.





Q. How does the 2019 SRP Report align with the Docket 4600 goals for the electric1

distribution system?2

A. In Table 1 of Section 5 of the 2019 SRP Report, the Company has detailed how the3

Report either advances, detracts, or remains neutral on achieving Docket 4600 goals for4

the electric distribution system.5

6

Q. How does the 2019 SRP Report coordinate with Power Sector Transformation7

(PST)?8

A. The 2019 SRP Report coordinates with the following PST Phase One Report goals: (1)9

Control the long-term costs of the electric system; (2) give customers more energy10

choices and information; and (3) build a flexible grid to integrate more clean energy11

generation. The 2019 SRP Report coordinates with these goals through NWA12

opportunities. SRP has the potential to control the long-term costs of the electric system13

by proactively searching for potential NWA opportunities to be implemented on the14

electric distribution grid instead of the traditional wires option at lower costs to15

customers. NWA opportunities are natively cost-effective, and several different types of16

environmentally-responsible technologies and solution may be implemented as an NWA17

solution. SRP provides customers with more energy choices and information through18

programs such as NWA participation opportunities. SRP is designed to build a flexible19

grid to integrate more clean energy generation through NWA opportunities, initiation of20





the Rhode Island System Data Portal, and engagement with third-party solution1

providers.2

3

The 2019 SRP Report also coordinates with the following PST Phase One Report4

recommendations: (1) Synchronize filings related to Distributed System Planning; (2)5

Improve forecasting; (3) Establish customer and third-party data access plans; and (4)6

Compensate locational value. SRP has synchronized with Distribution System Planning7

and the ISR filing to a certain extent, in that potential NWA opportunities are screened8

for as part of DSP and that SRP takes into account the annual electric peak load9

forecasting. The 2019 SRP Report currently includes information on forecasted electric10

load growth for the main purpose of identifying and coordinating with potential NWA11

opportunities. SRP establishes customer and third-party data access through the Rhode12

Island System Data Portal. The 2019 SRP Report presents the Company’s research and13

findings on locational incentive analysis for Rhode Island and details the Company’s14

commitment to stakeholder engagement and discussion regarding locational incentives in15

Rhode Island.16

17

Please see Section 4 of the 2019 SRP Report for more detail regarding SRP’s18

coordination with PST.19





Q. What is the Company’s coordination between SRP and other required Company1

filings in Rhode Island?2

A. The Company is working to bring the SRP Report in line with the other state filings the3

Company submits to ensure a cohesive and comprehensive plan framework and4

implementation. The Company has coordinated with the Energy Efficiency (EE) Plan to5

ensure that efforts are not being duplicated. The Company continues further coordination6

between SRP and other required Company filings such as the Infrastructure, Safety, and7

Reliability Plan (ISR Plan), and the Renewable Energy Growth (RE Growth) Program.8

9

In addition, the Company recognizes the desire to more fully implement the entire NWA10

and locational incentive effort with the work proposed in a particular year’s ISR Plan11

filing. To assist with this effort, the Company will host quarterly NWA/Locational12

Incentive meetings to provide further transparency to the Rhode Island Division of Public13

Utilities and Carriers (Division) and the Rhode Island Office of Energy Resources14

(OER).15

16

Q. Please explain how the 2019 SRP Report is structured.17

A. The 2019 SRP Report, includes the System Reliability Procurement funding request for18

CY 2019. The 2019 SRP Report itemizes the recommended work activities by19

project/program and provides budgets for O&M expenses for the respective SRP projects20

and programs. After the end of the calendar year, the Company trues up the SRP21





Report’s projected expense levels used for establishing the revenue requirement to actual1

or allowed investment and expenditures on a cumulative basis and reconciles the revenue2

requirement associated with the actual investment and expenditures to the revenue billed3

from the rate adjustments implemented at the beginning of each calendar year.4

5

Q. Please describe the categories of work activities that are included in the 2019 SRP6

Report to address service reliability.7

A. The Company’s overall objective in preparing the 2019 SRP Report is to arrive at a8

budget plan that is the optimal balance in terms of making the investments necessary to9

improve the performance of the electrical distribution system, thereby, resulting in10

maintaining the overall reliability of the system, while also ensuring a cost-effective use11

of available resources. Therefore, the 2019 SRP Report includes the investment needed12

to: meet state and federal regulatory requirements applicable to the electric system;13

address load growth/migration; maintain reliable service; sustain asset viability through14

targeted investments driven primarily by condition; and engage in efforts that support this15

work.16

17

Q. Please summarize the categories of System Reliability Procurement spending18

covered by the 2019 SRP Report.19

A. The proposed 2019 SRP Report addresses the following budget categories for CY 2019,20

or the twelve-month calendar year ending December 31, 2019: spending on the21





Marketing & Engagement Plan for the Rhode Island System Data Portal; the Customer-1

Facing Program Enhancement Study; and for the evaluation process of the Requests for2

Proposals (RFPs) for the three South County East NWA Projects.3

4

Q. Please review the CY 2019 SRP Funding Request.5

A. The funding request of the 2019 SRP Report is associated with three key work categories:6

(1) the Marketing & Engagement Plan; (2) the Customer-Facing Program Enhancement7

Study; and (3) the South County East NWA RFP Evaluation. The table below8

summarizes the proposed spending for each of these key work categories for CY 2019.9

10Summary of 2019 SRP Funding Request11

SRP Section SRP Initiative Cost

6.2 Marketing & Engagement Plan $124,800

11.4 Customer-Facing Program Enhancement Study $175,000

10.3 South County East RFP Evaluation $30,000

Total $329,800

As shown in the table above, the Company proposes a total of $329,800 for the funding12

request for SRP projects and programs.13

The Marketing & Engagement Plan has $124,800 allocated in the funding request for the14

Company to perform marketing and raise awareness with third-party solution providers15

and the public about the Rhode Island System Data Portal.16

17





The Customer-Facing Program Enhancement Study has $175,000 allocated in the1

funding request for the Company to perform market research, evaluate and test novel2

approaches on incentivizing customer behavior in a way that can be used to address3

electrical distribution-level constraints.4

5

The South County East RFP Evaluation has $30,000 allocated in the funding request for6

the Company to perform evaluations on project bid responses for the three South County7

East NWA Projects.8

9

Q. Is the Company able to provide a list and detail of the specific projects that will be10

undertaken in each of the work categories of the 2019 SRP Report?11

A. Yes. In the 2019 SRP Report, the Company has provided detail on the specific projects12

within each work category that would be undertaken in CY 2019 as part of the 2019 SRP13

Report. The Company and the Parties have reviewed these planned projects and the14

overall spending levels and have reached consensus regarding the appropriate investment15

levels for CY 2019.16

17

IV. CONSIDERATION OF NWAS IN SYSTEM PLANNING18

Q. Please provide a concise summary of the NWA screening process.19

A. The NWA screening process uses the following criteria to identify possible solutions to20

reduce, avoid or defer the T&D wires solution over an identified time period:21





a. The need is not based on asset condition;1

b. The wires solution, based on engineering judgment, will likely cost more than $12

million;3

c. If load reductions are necessary, then they are expected to be less than 20 percent of4

the relevant peak load in the area of the defined need;5

d. Start of wires alternative construction is at least 36 months in the future; and6

e. At its discretion the utility may consider and, if appropriate, propose a project that7

does not pass one or more of these criteria if it has reason to believe that a viable8

NWA solution exists, assuming the benefits of doing so justify the costs.9

The last screening criterion is used in cases where an NWA may not defer the entire T&D10

project, but could defer part of the overall scope of the project. This is referred to as11

“partial” or “hybrid” NWA.12

13

Q. Why are past Area Studies being re-evaluated for potential NWA opportunities14

again?15

A. The Company recognizes that NWA technology costs change over time, and projects that16

might not have been viable at the time of study might become viable if technology costs17

decrease over time. Additionally, the load relief need is still present for the town of18

Providence and for the East Bay area.19

20





Q. What is the Company’s proposed work on the Rhode Island System Data Portal in1

2019?2

A. The Company proposes further enhancement of the Portal by completing the following3

actions:4

Identify locations where electric vehicle (EV) level 3 charging stations can5

potentially be implemented or installed, without negatively affecting the health or6

rating of an electric grid feeder. Level 3 charging stations are units that are rated7

at approximately 300 kW. Action to be complete by September 30, 2019.8

Identify areas where large non-EV public transportation fleets are located in order9

to forecast where potential fleet conversion of non-EV to EV may occur. Action10

to be complete by July 1, 2019.11

Include redacted area studies in the Portal by December 31, 2019.12

13

The Company also commits to having a discussion with the Parties regarding an “Open14

RFP” situation, which would entail posting previously-identified potential NWA15

opportunities that were determined to be non-economic or not cost-effective.16

17





Q. How will the Company be compensated for the proposed work on the Rhode Island1

System Data Portal in 2019?2

A. The Company has not included any Portal work in the 2019 SRP Funding Request.3

Instead, the Company, in agreement with the Parties, has set two of the Portal proposed4

work items as separate action-based incentive items. The Company intends to complete5

this proposed work and therefore earn compensation through the SRP Incentive6

Mechanism.7

8

V. TIVERTON-LITTLE COMPTON NWA PROJECT9

Q. Please provide a concise background of the Tiverton-Little Compton NWA Project.10

A. The purpose of the Tiverton-Little Compton NWA Project (TLC NWA Project) was to11

provide load relief in the same geographical footprint as the Tiverton NWA Pilot.12

13

The Little Compton Battery Storage (LCBS) Project started as an RFP solicitation for an14

integrated NWA solution, which was previously approved within the 2017 SRP Report in15

Docket 4655 as part of the Tiverton Pilot. The Company completed the RFP in early16

2017, resulting in a battery storage project as the winning bid. The Company then17

proposed the LCBS Project in the 2018 SRP Report to resolve the need in the Tiverton-18

Little Compton area, which was subsequently approved in Docket 4756. However,19

during the process of implementation, the LCBS Project was delayed and experienced20

project scope creep; the LCBS Project was not installed for the summers of 2017 or 2018.21





In light of these delays, the Company decided to reissue the RFP for this potential NWA1

opportunity in the original filing of the 2019 SRP Report on October 15, 2018. The2

Company correspondingly reframed the LCBS Project as the “Tiverton-Little Compton3

NWA Project.” This was done in consideration of reissuing the RFP and to maintain a4

technology agnostic characteristic for third-party solution providers for the RFP process.5

6

Following the October filing, National Grid’s internal forecasting group issued the 20197

Electric Peak Forecast in early November 2018. National Grid has recently re-evaluated8

the loading concern in early December of 2018, which is the basis of the NWA project9

and concluded that the loading concern has been mitigated through natural distributed10

generation development. Working collaboratively with the Division, the OER, and the11

other stakeholders, the Company recognizes that the NWA process in general is still12

relatively new to all stakeholders and requires continuous review. The Company does13

plan to work on lessons learned with stakeholders to review the process utilized in both14

the Tiverton/Little Compton area and the rest of state to better capture the way this sort15

of ‘natural distributed generation’ affects the Company’s load forecasting methodology16

through its on-going NWA discussions and quarterly meetings. At this time, National17

Grid proposes to remove the Tiverton Little Compton NWA RFP from the 2019 SRP.18

19





Q. Please provide additional details on why the TLC NWA Project should be removed1

from the SRP Report.2

A. Since the 2017 analysis that informed the 2018 SRP Report, distributed generation has3

naturally occurred in the area at approximately 900 kilowatts. Also, in-queue distributed4

generation currently totals over 6,000 kilowatts. Lastly, the most recent 2019 Electric5

Peak Forecast shows negative growth rates for this area. The existing distributed6

generation and current forecast lead to projected loading on the 33F4 circuit of 98% or7

less. The in-queue distributed generation may reduce this further depending on hour of8

the future peak. As a result of these three factors, the original loading driver for the9

NWA project has reduced such that there is no planning criteria issue.10

11

2017 Analysis – Basis of 2018 SRP Report12

13

%SN = Percent Summer Normal Rating14

15

16

17

18

Amps %SN Amps %SN Amps %SN

TIVERTON 33F3 428 89% 435 91% 446 93%

TIVERTON 33F4 508 111% 517 113% 529 116%

Feeder 2019 2025 2030

Projected Load

Substation





2019 Analysis – Current1

2

%SN = Percent Summer Normal Rating3

4

Q. Please provide additional detail on the in-service and in-queue distributed5

generation that has developed in this area since the original analysis.6

A. The following tables shows the in-service and in-queue distributed generation that has7

developed over 2017 and 2018 for the area of concern (33F3 and 33F4 circuit area).8

9

10

For this unique analysis, National Grid removed a 10,000-kilowatt proposal on the 33F4.11

This was done to remove possible debate on interconnection feasibility with no impact on12

the conclusion.13

14

15

Amps %SN Amps %SN Amps %SN

TIVERTON 33F3 359 75% 348 73% 342 71%

TIVERTON 33F4 446 98% 433 95% 425 93%

Substation Feeder

Projected Load

2019 2025 2030

TIVERTON 33F3 570 2520TIVERTON 33F4 340 14100

TOTAL 910 16620

Proposed

Since 2017 kWSubstation Feeder

Interconnected

since 2017 kW





VI. SOUTH COUNTY EAST NWA PROJECTS1

Q. What is the Company’s proposal for the South County East NWA Projects?2

A. The Company’s proposal for the 2019 calendar year is to identify technologies and/or3

methodologies through the RFP bid process that, when implemented, will provide an4

NWA solution for the specific South County East project area.5

6

Q. What is the Company’s proposed funding plan for the South County East NWA7

Projects?8

A. The Company proposes $30,000 for the South County East NWA Projects in calendar9

year 2019. This accounts for approximately $10,000 for each of the three project RFP10

evaluations. This corresponds with the Company’s plan and proposal for the South11

County East NWA Projects for calendar year 2019.12

13

VII. CUSTOMER-FACING PROGRAM ENHANCEMENT STUDY14

Q. What is the purpose of the Customer-Facing Program Enhancement Study?15

A. The purpose of the proposed Customer-Facing Program Enhancement Study16

(Enhancement Study) is to evaluate and test customer-side opportunities beyond energy17

efficiency that are cost effective and provide the path to lower supply and delivery costs18

to customers in Rhode Island. The specific approach taken by the Enhancement Study is19

to develop a long-term, peak load reduction program for Rhode Island that will employ20

low-cost and easy-to-deploy methods to address distribution-level constraints. The21





Company plans to integrate learnings from the Enhancement Study in future NEC1

programs and projects that engage customers in Rhode Island, because, although the2

Enhancement Study will focus on addressing distribution-level constraints, it is3

anticipated that the results of the Enhancement Study will be able to be used more4

broadly to improve the efficiency and cost-effectiveness of other types of customer-5

facing programs (e.g., Energy Efficiency, Residential Energy Storage, Electric Vehicle6

Charging).7

8

Q. What does the Company intend to achieve with the Customer-Facing Program9

Enhancement Study?10

A. The objective of the Enhancement Study is to evaluate and test novel approaches to11

incentivize customer behavior that can be used to address electrical distribution-level12

constraints and improve environmental, economic, and grid performance outcomes from13

residential and small commercial (R&SC) customer-facing programs.14

15

Q. What is the Company’s goal in Phase 1 of the Enhancement Study? When does16

Phase 1 occur?17

A. The goal of Phase 1 is to develop a R&SC Customer Peak Load Reduction Program18

Enhancement Plan (Program Plan) for the state. A vendor(s) with behavioral science and19

customer research expertise will perform a thorough literature review and use the lessons20

learned from other customer peak load reduction programs, direct assessments, and21





Rhode Island customer demographics, to develop novel customer engagement approaches1

based on behavioral economic and other behavioral science principles that are designed2

to increase customer enrollment, participation, and retention for R&SC customer classes.3

Novel approaches could include economic and non-economic motivations for behavior,4

based on accepted models of human behavior and social marketing. This may include5

approaches such as behavioral nudges, social recognition and peer leadership, and6

programs to increase perceived efficacy and behavioral control. Phase 1 occurs from7

January 1, 2019 until December 31, 2019.8

9

Q. Is the Customer-Facing Program Enhancement Study cost-effective? Please10

provide clear detail with respect to the different phases of the Enhancement Study.11

A. The Enhancement Study is primarily research, development and demonstration during12

Phases 1 through 3. Therefore, there will be very few benefits over the initial13

Enhancement Study period compared to project costs. In the ten years following Phase 314

(2023 through 2032), however, the Company plans to integrate learnings from the15

Enhancement Study in future programs and projects that engage customers in Rhode16

Island. Therefore, a BCA calculation was performed for the initial four-year17

Enhancement Study period (2019-2022) plus an additional 10-year period (2023-2032)18

over which time it is assumed a future Rhode Island peak load reduction enhancement19

program (Enhancement Program) will be deployed in other locations to address20

additional distribution-level constraints. The total benefits and costs associated with both21





the proposed Study and the future Program summed over the assumed 14-year period1

results in a Net Present Value (NPV) based BCR of 1.54. This means that the estimated2

benefits exceed the estimated costs over the 14-year period by 54%.3

4

Q. How does the Customer-Facing Program Enhancement Study apply to System5

Reliability Procurement and the goals of Docket 4600?6

A. The purpose of the Enhancement Study and the System Reliability Procurement (SRP)7

are identical, i.e., identify customer-side opportunities beyond energy efficiency that are8

cost effective and provide the path to lower supply and delivery costs to customers in9

Rhode Island. The Enhancement Study addresses barriers related to a specific SRP10

resource - i.e., demand response via on-demand usage reduction - designed to provide11

local system reliability benefits.12

13

The Enhancement Study supports the goals of Docket 4600. Specifically, the Study14

intends to:15

Provide for safe, clean, and affordable energy to customers in the long term by16

developing and executing an optimized customer-side demand response program.17

Strengthen the Rhode Island economy by engaging customers to help defer18

investments in traditional wires solutions;19





Address the challenge of climate change and help facilitate customer investment in1

their facilities using behavioral economics to encourage customers to participate in2

demand response events and reduce their energy use throughout the year using3

connected customer devices or other means; and4

Align Company, customer, and policy objectives and interests by developing and5

executing customer-facing programs that benefit the distribution grid, Rhode Island6

customers, and the Environment.7

8VIII. RHODE ISLAND LOCATIONAL INCENTIVES9

Q. Please provide a concise background of the Rhode Island Locational Incentives.10

A. The Company’s locational incentive research and analysis was conducted in 2017 under11

the option the Company has to offer a locational incentive pursuant to the RE Growth12

Program with stakeholder engagement from the Division and OER. The analysis13

followed a three-phase approach: 1) expedited method for screening feeders and peak14

analysis; 2) three approaches to understanding potential avoided cost benefits and 3) solar15

contribution to load reduction.16

17

The second step encompassed three different approaches to estimate potential benefits18

from load relief, both broadly and at specific locations: 1) system-wide avoided19

transmission and distribution cost; 2) feeder specific deferral value of distribution system20

upgrades as measured by the avoided revenue requirement NPV, multiplied by the21





probability of a spot load developing necessitating an upgrade; 3) time-value deferral1

NPV, similar to what has been used for the Tiverton Pilot area. Further details of the2

analysis are described in Section 12.1.1 through Section 12.1.3 of the 2019 SRP Report3

filed with the PUC on October 15, 2018.4

5

The analysis concluded that due to the lack of specific NWA opportunities, a successful6

history of offering multiple paths to solution providers by which to install DG in the state,7

and no load growth in the Rhode Island service territory, that no locational incentives8

should be proposed in the 2018 RE Growth filing.9

10

The analysis culminated with the Company presenting on the analysis and the results to11

the Rhode Island Division and OER on September 12, 2017. A copy of the presentation12

was provided as Appendix 5 in the 2019 SRP Report filed with the PUC on October 15,13

2018.14

15

Q. What is the Company’s summary proposal for the Rhode Island Locational16

Incentives?17

A. Under Rhode Island General Laws Chapter 39-26.6 - The Renewable Energy Growth18

Program, the Company proposes to further the work from the 2017 calendar year effort,19

as detailed in Section 12.1 of the 2019 SRP Report filed with the PUC on October 15,20

2018, by using the deferral value for specific NWA locations at South County East to21





provide a financial incentive for bidders to respond to when the NWA RFPs are issued1

late in 2018 as per the 2018 SRP Report. The Company elected to conduct the work for2

locational incentives within the SRP work plan rather than the RE Growth Program work3

plan to have a mechanism to pay for load relief from the NWA RFPs the Company issues4

within the SRP Plan. The Company is not proposing to provide locational incentives in5

the RE Growth Program at this time.6

7

To provide value back to customers, the Company initially suggests that the incentive8

uses no more than 60% of the deferral value on an annualized basis over the term of the9

deferral need, then estimating the number of kilowatt-hours needed in a location (load10

relief needed in kilowatts multiplied by the estimated hours the load relief is needed over11

the term of the deferral need) and calculating a per-kWh credit to be paid based on12

performance of the winning bidder’s project or program.13

14

The percent suggested as the deferral value was selected as a starting point to determine15

whether a bidder to an NWA RFP would find this value to be sufficient. It is important16

not to over-pay initially for NWA solutions for fear of setting future payment17

expectations. There are two main reasons the Company suggests using this 60% of the18

deferral value as a locational incentive for the RFPs: 1) for any non-wires alternative19

(NWA) to be net beneficial to customers, the Company cannot spend the same amount of20

money as it would on a traditional utility solution; and 2) the Company has yet to see that21





an NWA solution actually will defer a traditional utility solution, and therefore, there is a1

risk premium to employing NWAs.2

3

The specific details of this calculation are ongoing as they are part of the larger project to4

issue new RFPs for the South County East NWA projects which will not be released until5

later in calendar year 2018. The Company commits to continue stakeholder engagement6

and discussion regarding locational incentives in Rhode Island. With this input, the7

Company would determine the proper avenue for proposing such an incentive and8

appropriately file for approval to pay these incentives showing the projects the Company9

expects to fund with the incentives.10

11

Q. What is the current status of Distributed Generation (DG) growth in Rhode Island?12

A. As presented at the Rhode Island Quarterly DG Interconnection Meeting in July 2018 and13

as illustrated in the tables below, interconnection trends for both DG applications14

received and for DG interconnected have trended upwards year-over-year since 2011, in15

terms of the number of applications and megawatts.4 This trend is applicable to both16

complex and simple projects.517

18

4 The numbers for 2018 have not been finalized since the full 2018 calendar year has not yet completed.

5 A simple project is considered any distribution project that is under 10 kW for 1-phase lines or 25 kW for 3-phaselines, while a complex project is over this threshold.





Rhode Island Complex Interconnection Application Trends1

Received Applications, Complex Interconnected Applications, ComplexMW Apps MW Apps

2011 25.0 27 1.0 82012 36.0 60 7.2 122013 23.0 53 13.3 192014 23.2 47 17.8 222015 58.9 102 3.3 272016 134.2 139 21.1 522017 297.3 149 23.8 552018 349.9 161 5.5 27Total 947.6 738 93.0 222

2

Rhode Island Simplified Interconnection Application Trends3

Received Applications, Simple Interconnected Applications, SimpleMW Apps MW Apps

2011 0.2 30 0.2 212012 0.2 41 0.3 452013 0.3 77 0.2 512014 0.6 127 0.4 772015 3.2 599 1.9 3292016 10.1 1,724 8.1 1,3512017 12.6 2,237 10.8 1,8322018 7.7 1,313 4.4 774Total 34.8 6,148 26.4 4,480

4

Q. What is the current status of electric peak load in Rhode Island?5

A. Although the Locational Incentive analysis was performed in the summer of 2017, the6

current Rhode Island 2018 Electric Peak (MW) Forecast for the long-term (2018-2032),67

provided in Appendix 1 of the 2019 SRP Report filed with the PUC on October 15, 2018,8

6 Gredder, Joseph F, and Pedram Jahangiri. “Rhode Island 2018 Electric Peak (MW) Forecast; Long-Term: 2018 to2032.” Rhode Island System Data Portal, National Grid, 10 Jan. 2018, http://ngrid-ftp.s3.amazonaws.com/RISysDataPortal/Docs/RI_Forecast_PEAK_2018_Report_rev1_Jan2018.pdf.





continues to support the conclusion that the Rhode Island service territory is not1

experiencing load growth. As explained on pages four and five of the Rhode Island 20182

Electric Peak (MW) Forecast, the service territory is experiencing negative growth of -3

0.1% annually over the next fifteen years.4

5

Additionally, the Company presented at the Rhode Island Quarterly DG Interconnection6

Meeting in July 2018 that, by the end of 2018, the Company forecasts that Rhode Island’s7

electric load will be reduced by 1.2% from historical load levels. This reduction is based8

on an assumption of solar DG having a 21% annual average capacity factor and9

forecasted 25 MW of solar. By the end of 2019, the Company forecasts that Rhode10

Island’s electric load will be reduced an incremental 0.4%, assuming 21% annual average11

capacity factor and forecasted 32 MW of solar.12

13

Q. What does the Company expect the future of Locational Incentives in Rhode Island14

to be?15

A. In the Company’s last general rate case in consolidated Docket Nos. 4770/4780, the PUC16

approved an Amended Settlement Agreement (Settlement Agreement), which reflected17

modifications approved by the PUC at its August 3, 2018 Open Meeting. Included in the18

Settlement Agreement is the approval of an electric transportation initiative in Rhode19

Island. Additionally, the PUC’s decision in this proceeding provides that the utility must20

include opportunities for EVs in distribution level planning. While factors such as21





advances in energy efficiency, distributed solar, and behind-the-meter storage decrease1

utility load, the electrification of transportation and heat are expected to reverse that2

trend. The expected increase in DC Fast Charging that results from the Power Sector3

Transformation electric transportation initiative and Rhode Island’s Zero Emission4

Vehicle (ZEV) Draft Plan goals for growing EV adoption more than 40-fold by 2025 will5

have to be managed with appropriate electrical service and distributed generation and6

storage resources to effectively prevent system overloading and to avoid utility peak7

demand charges. The Company does see an opportunity in the future to offer locational8

incentives in locations where load on the electric distribution system is increasing due to9

the growth of electric vehicle supply equipment (EVSE) and electric heat.10

11

IX. SRP INCENTIVE MECHANISM PROPOSAL12

Q. What is the SRP Incentive Mechanism?13

A. The SRP Incentive Mechanism is a system that incentivizes the Company to complete14

actions or implement distributed energy resources (DERs) that would otherwise have a15

higher risk factor, such as NWA solutions in comparison to traditional wires solutions, or16

does not have cost recovery associated with the action.17

18

Q. What are the Action-Based SRP Incentives for 2019? What is the reason for these19

incentive items?20

A. The Action-Based SRP Incentives for calendar year 2019 are listed in the table below.21





Summary of Action-Based SRP Incentives1

Section Action Date % of 2019SRP

BudgetRhode Island SystemData Portal

Identify areas where large non-EVpublic transportation fleets are located

July 1, 2019 2%

Rhode Island SystemData Portal

Identify locations where EV level 3charging stations can potentially be

implemented or installed

September30, 2019

2%

South County EastNWA Projects

Awarded and completion of firstvendor milestone for all 3 projects

December31, 2019

2%

2

These incentive items will encourage the Company to perform further work on the Rhode3

Island System Data Portal, as detailed by the first two incentive action items, and to make4

significant progress on the South County East NWA Projects. Additionally, the Rhode5

Island System Data Portal does not have cost recovery in the 2019 SRP Report for6

performing this further work because the Company, in agreement with the Parties,7

reasons that the Action-Based Incentive is an appropriate mechanism for compensation8

for this work. The South County East NWA Projects have an action-based incentive to9

encourage the Company to implement NWA solutions because NWA solutions are10

recognized as having a higher risk factor than traditional wires solutions.11

12





Q. When will the Company propose the incentive earnings for a specific year’s action-1

based incentive item?2

A. The Company will propose the incentive earnings for a specific year’s action-based3

incentive items in the SRP Report that covers the calendar year two years after when the4

specific action-based incentive items were first proposed. For example, the action-based5

incentive items for calendar year 2018 will have their incentive earnings proposed in the6

2020 SRP Report. This will allow for full calendar year assessment for action-based7

incentive items.8

9

Q. What is the Savings-Based SRP Incentive?10

A. The Savings-Based SRP Incentive is the part of the SRP Incentive Mechanism that11

encompasses incentives for the Company to install DERs as a result of SRP initiatives.12

The Company will be obligated to demonstrate that DERs were installed as a result of the13

SRP initiatives. This demonstration would require: 1) an affidavit from the DER provider14

that Company marketing influenced their decision to site, and 2) confirmation that the15

DER was installed in the current year of the SRP plan (i.e., calendar year 2019). For the16

Company to earn savings-based incentives on them, the DERs must be deemed cost-17

effective according to the Rhode Island cost-effectiveness framework established in the18

PUC’s Docket 4600-A Guidance Document.19

20

21





X. CONCLUSION1

Q. In your opinion does the 2019 SRP Report fulfill the requirements established in2

relation to the safety and reliability of the Company’s electric distribution system in3

Rhode Island?4

A. Yes. The 2019 SRP Report is designed to establish the NWA and SRP-related activities5

in Rhode Island that are necessary to meet the needs of Rhode Island customers and6

maintain the overall safety and reliability of the Company’s electric distribution system.7

The Company believes that the proposed 2019 SRP Report accomplishes these8

objectives. As such, the PUC’s approval of the proposed 2019 SRP Report is essential9

for the Company to continue maintaining a safe and reliable electric distribution system10

for its Rhode Island customers.11

12

Q. Does this conclude this testimony?13

A. Yes, it does.14

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